It will be appreciated by those skilled in the art that inorganic scale formation associated with brine solutions produced from oil and gas wells has been a major issue, leading to production restrictions and costly downtime to remove the scale. In the past few decades there have been a significant number of studies to understand the mechanism of scaling at elevated temperatures and pressures, which correspond to well operating conditions, and developing models to predict the change in scaling conditions over the life cycle of the oil and gas wells.
Stiff and Davis studied the tendency of CaCO3 scaling of oil field waters (1). Oddo and Tomson derived a simplified method of calculating CaCO3 saturation at high temperatures and pressures (2). Oddo and Tomson also investigated and introduced new saturation indices for barium, strontium, magnesium and calcium sulfates and calcium carbonates (3). Haaberg, Selm and Granbakken investigated scale formation in reservoir and production equipment during oil recovery by presenting a reliable model for the solubility products of scale-forming minerals (4). Straub investigated solubility of CaSO4 and CaCO3 at temperatures between 182° C. to 316° C. (5). It was concluded that CaSO4 and CaCO3 solubility decreases with increasing temperature (5). Yeboah, Somauh, and, Saeed presented a new reliable model for predicting oilfield scale formation (6). This model, in contrast to other models which predict only scaling potential using thermodynamics and limited solubility data, predicts the potential and deposition profile based on extensive thermodynamic and kinetic data.
There are numerous models available in the literature (Ref. 1) which address the scale formation potential through solubility index computations. These models are primarily based on stoichiometry of the brine and do not adequately address the reaction rate. Also, a majority of the research has been performed by academia which is somewhat limited to low flow rate and relatively low pressure conditions. The tube tests conducted by flowing a brine solution through a capillary tube at high temperature (and low pressures on the order of a few hundred psi) are effectively utilized for inhibitor comparisons.
These are not suitable for predicting scale growth for more complex geometry, such as that of an interval control valve of the type used to regulate fluid flow into a tubular string. There also appears to be a shortage of mechanical strength data for the scale materials formed over a range of temperatures and pressures commonly encountered in a well downhole.